U.S. patent application number 11/770097 was filed with the patent office on 2008-02-07 for method for improved well control with a downhole device.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. Invention is credited to Jens Uwe Bruns, Sven Krueger.
Application Number | 20080029306 11/770097 |
Document ID | / |
Family ID | 38829673 |
Filed Date | 2008-02-07 |
United States Patent
Application |
20080029306 |
Kind Code |
A1 |
Krueger; Sven ; et
al. |
February 7, 2008 |
Method for Improved Well Control With A Downhole Device
Abstract
A drilling system includes a downhole well control device that
can be used to control out-of-norm wellbore conditions. The
downhole well control device can control one or more selected fluid
parameters. The well control device in cooperation or independent
of surface devices exerts control over one or more drilling or
formation parameters to manage an out-of-norm wellbore condition.
An exemplary well control device hydraulically isolates one or more
sections of a wellbore by selectively blocking fluid flow in a pipe
bore and an annulus. The control device also selectively flows
fluid from the pipe bore to the annulus. A communication device
provides on-way or bidirectional signal and/or data transfer
between the controller(s), surface personnel and the well control
device. Exemplary application of the well control device include
controlling a well kick, controlling drilling fluid being lost to
the formation and controlling a simultaneous kick and loss.
Inventors: |
Krueger; Sven; (Winsen,
DE) ; Bruns; Jens Uwe; (Burgdorf, DE) |
Correspondence
Address: |
MADAN, MOSSMAN & SRIRAM, P.C.
2603 AUGUSTA DRIVE
SUITE 700
HOUSTON
TX
77057-5662
US
|
Assignee: |
BAKER HUGHES INCORPORATED
2929 Allen Parkway, Suite 2100
Houston
TX
77019-2118
|
Family ID: |
38829673 |
Appl. No.: |
11/770097 |
Filed: |
June 28, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60818071 |
Jun 30, 2006 |
|
|
|
Current U.S.
Class: |
175/210 ;
175/48 |
Current CPC
Class: |
E21B 34/06 20130101;
E21B 33/06 20130101; E21B 21/103 20130101 |
Class at
Publication: |
175/210 ;
175/048 |
International
Class: |
E21B 17/18 20060101
E21B017/18; E21B 21/08 20060101 E21B021/08 |
Claims
1. A method for controlling flow in a wellbore formed in a
subterranean formation, comprising: conveying a drill string into
the wellbore; sealing a bore of the drill string; and sealing an
annulus between the drill string and a wellbore wall.
2. The method of claim 1 further comprising circulating a fluid
into the wellbore, wherein the fluid is one of: (i) lost
circulation material, (ii) a cement; and (iii) a drilling mud
having a mud weight greater than a mud weight of a drilling mud
previously circulated in the wellbore.
3. The method of claim 1 further comprising circulating a fluid
uphole of the sealed annulus.
4. The method of claim 4 further comprising using a valve to
circulate the fluid between the bore and the annulus.
5. The method of claim 4 further comprising inflating a packer to
seal the annulus, and controlling the valve to inflate the
packer.
6. The method of claim 4 further comprising transmitting data to
the surface by controlling the valve.
7. The method of claim 1 further comprising measuring a shut-in
pressure of the wellbore.
8. The method of claim 7 wherein the shut-in pressure is measured
downhole of the annulus seal.
9. The method of claim 7 further comprising unsealing the bore of
the drill string, and wherein the shut-in pressure is measured
while the annulus is sealed and the bore is unsealed.
10. The method of claim 1 further comprising sealing the bore and
the annulus after detecting an out-of-norm condition.
11. The method of claim 10 wherein the out-of-norm condition is one
of: (i) a kick in the wellbore, (ii) a fluid loss into the
formation, and (iii) an underground blowout.
12. An apparatus for controlling flow in a wellbore formed in a
subterranean formation, comprising: (a) a first flow control device
selectively controlling a flow of a fluid in a bore of a wellbore
tubular; (b) a second flow control device selectively controlling a
flow of a fluid in an annulus between the wellbore tubular and a
wellbore wall wherein the first and second control devices
cooperate hydraulically isolate an upper section of the wellbore
from a lower section of the wellbore; and (c) a third flow control
device selectively controlling a flow between the annulus and the
bore.
13. The apparatus of claim 12 wherein the third flow control device
selectively controls flow in the upper section of the wellbore.
14. The apparatus of claim 12 further comprising a drill string
have a drill bit at a distal end, the first, second and third flow
control devices being disposed along the drill string.
15. The apparatus of claim 12 wherein one of the first flow control
device, the second flow control device and the third flow control
device is responsive to a surface transmitted signal.
16. The apparatus of claim 12 further comprising a downhole
controller in communication with the surface and transmitting a
signal indicative of an operating condition of one the first flow
control device, the second flow control device and the third flow
control device.
17. A method for drilling a wellbore in a subterranean formation,
comprising: rotating a drill bit at an end of a drill string to
form the wellbore; measuring at least one parameter of interest to
determine the occurrence of an out-of-norm condition; and
activating a well control device disposed along the drill string to
form an upper wellbore section that is hydraulically isolated from
a lower wellbore section.
18. The method of claim 17 further comprising increasing a mud
weight of a drilling fluid in the upper wellbore section.
19. The method of claim 18 further comprising measuring a shut-in
pressure at a location proximate to the lower wellbore section;
transmitting the measured shut-in pressure to the surface, and
determining a mud weight for the drilling fluid to be circulated in
the upper wellbore section.
20. The method of claim 17 further comprising transmitting a
pressure pulse from the surface to activate the well control
device.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application takes priority from U.S. Provisional Patent
Application Ser. No. 60/818,071, filed Jun. 30, 2006.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to systems and methods for
well control during oilfield operations in situations such as kicks
of formation fluids, mud losses and underground blowouts.
[0004] 2. Description of the Related Art
[0005] During construction or servicing of a hydrocarbon producing
well, an operator can encounter a number of undesirable conditions
that can pose a hazard to equipment and personnel. One undesirable
condition is a "kick." During drilling, a high pressure formation
fluid can invade the well bore and displace drilling fluid from the
well. The resulting pressure "kick" can lead to a well blow-out at
the surface. Conventionally, during drilling, the mud weight of a
drilling fluid circulated in the well is selected to provide a
hydrostatic pressure that minimizes the risk and impact of a
"kick." Additionally, drilling rigs use surface blowout preventers
to protect against the uncontrolled flow of fluids from a well.
When activated, blowout prevention systems "shut-in" a well at the
surface to seal off and to thereby exert control over the kick. A
typical blowout preventer system or "stack" usually includes a
number of individual blowout preventers, each being designed to
seal the well bore and withstand pressure from the wellbore.
Another undesirable condition is a loss of drilling fluid into a
formation. That is, in some instances, the drilling fluid pumped
into the wellbore is at a pressure that causes some or all of the
drilling fluid to penetrate into the formation rather than flow
back up to the surface. A loss is usually treated by circulating a
lost circulation material (LCM) into the wellbore. The LCM usually
includes particles that plug and seal the fractured or weak
formation. Yet another undesirable condition is an underground
blowout, which is generally understood as an undesirable subsurface
cross flow between two reservoirs intersected by a wellbore. Such a
cross flow can be caused when a drilling crew activates a surface
blowout preventer to suppress and control a kick. The shut-in well
can cause an annulus pressure increase that fractures one or more
zones in an open hole region. Drilling fluid is then lost to this
fractured zone. This condition can be require a combination of
measures, including the use of LCM and well shut-in, to
control.
[0006] The present invention provides systems and devices adapted
to enhance control over the above-described undesirable conditions
as well as other out-of-norm conditions.
SUMMARY OF THE INVENTION
[0007] In aspects, the present invention provides a drilling system
that includes a downhole well control device that can be used to
control one or more out-of-norm conditions that can occur when
drilling or servicing a well; e.g., a kick, an underground blowout
or a fluid loss into a formation. By out-of-norm condition, it is
meant any condition that could pose a hazard to personnel, the
environment, or equipment. Out-of-norm conditions also include
conditions that could interrupt work activities or damage the well.
The downhole well control device can control fluid pressure, the
rate of flow, the direction of flow and/or the conduits or paths in
which one or more fluids flow. The fluids controlled can be
engineered fluids such as a drilling fluid, cement, and fluids
containing LCM as well as formation fluids such as gas, oil and
water. The well control device in cooperation or independent of the
surface blow-out preventer and other surface equipment exerts
control over one or more drilling or formation parameters to manage
an out-of-norm wellbore condition.
[0008] In some embodiments, the well control device is configured
to hydraulically isolate one or more sections of a wellbore. An
exemplary well control device includes a pipe bore flow control
device to selectively block fluid flow in a pipe bore, an annulus
flow control device that selectively blocks fluid flow in a well
annulus, and a bypass flow control device that selectively flows
fluid from the pipe bore to the annulus. Depending on the settings
of each of these flow devices, e.g., open, closed, or throttled, an
out-of-norm condition associated with one or more of these isolated
wellbore section can be treated independently, sequentially or
concurrently. In embodiments, a surface controller and/or a
downhole controller controls the well control device. A
communication device provides one-way or bidirectional signal
and/or data transfer between the controller(s), surface personnel
and the well control device. In one arrangement, the surface
controller transmits a downlink encoded with instructions for
operating the well control device. The surface controller can also
receive uplinks from the downhole controller that are encoded with
data relating to sensor measurements, e.g., measured pressure, the
operating status of the downhole well control device, or other such
data. The downhole controller can be programmed to automatically
control the well control device without downlink instructions
and/or send uplink signals prior to activating or de-activating the
well control device. Suitable communication devices can utilize
flow variations, pressure pulses, EM signals, acoustic signals,
signals conducted via metal or optical wires, and/or controlled
manipulation of a work string. In one embodiment, the bypass valve
may be used to generate pressure pulses and/or flow variations to
transmit data to the surface.
[0009] One exemplary application of a well control device is to
control a well kick. Upon detection of a kick, the well control
device closes the pipe bore, seals off the annulus, and opens the
bypass valve. Next, based on available information, e.g.,
surface/downhole measured pressure, a "kill" mud weight is
determined and pumped into the wellbore. The open bypass valve
allows circulation of the kill mud above the well control device to
circulate out formation fluids that were not shut-in below the well
control device. After the annulus above well control device is
filled with the kill mud, the well control device is de-activated
to provide normal flow through the pipe bore and annulus.
[0010] Another exemplary application of a well control device is to
control drilling fluid being lost to the formation due to weak
formations. After a loss is detected, the well control device is
activated to stop flow in the annulus and pipe bore and the bypass
valve is opened. If mud is lost above the well control device, lost
circulation material (LCM) is circulated using the open bypass
valve. After losses are cured, the well control device is
de-activated. If mud is lost below the well control device, the
entire annulus above the well control device is maintained full of
mud to prevent a kick in the open hole section above the well
control device and below a casing shoe. Next, cuttings are
circulated out of the wellbore above the well control device and
LCM is added to the mud being pumped down. At this point, there are
at least three options for pumping LCM into the loss zone below the
well control device. One option is to close the bypass valve, open
the pipe valve and force LCM into the loss zone until losses are
stopped. Thereafter, the well control device is deactivated. A
variation to this option is to use cement instead of LCM, which may
require pulling the drill bit off bottom. A second option is to
keep the bypass valve open and use a non-return valve to prevent
flow from the annulus into the pipe bore through the bypass valve.
Next, LCM is circulated until full returns are seen at surface,
which indicates that losses have stopped. Thereafter, the well
control device is de-activated. A third option is to keep the
bypass valve open without using a non-return valve. The bypass
valve, however, uses a restricted flow to prevent flow from the
annulus into the pipe bore. The well control device is de-activated
after losses have stopped.
[0011] Yet another exemplary application of a well control device
is to control a simultaneous kick and loss, i.e., an underground
blowout. After detection of an underground blowout, the well
control device is activated in a manner previously described.
Losses above the well control device are treated by circulating LCM
until losses have stopped. After losses are stopped, kill mud, with
or without LCM, is circulated above the well control device.
Thereafter, the previously described steps for controlling a kick
are initiated. For losses below the well control device and the
kick above the well control device, a standard kill procedure
utilizing surface equipment is applied to kill the kick after
refilling the annulus with mud. In a variant, the kill procedure
may be preceded by a preparation for cementing the loss zone. After
the well is killed above the well control device, two options are
available. One option is to add LCM to the kill mud, de-activate
the well control device, and start circulation. Another option is
to first pump LCM into the formation and start circulation only
after losses have stopped.
[0012] In another aspect, embodiments of the present invention can
utilize downhole pressure measurements to determine parameters such
as wellbore pressure. For example, conventionally, after a surface
shut-in, the stand pipe pressure is measured to determine wellbore
pressure. Embodiments of the present invention can, after
activation of the well control device, measure the pressure of the
fluid in the annulus or the pipe bore below the well control device
to determine wellbore pressure. This pressure measurement can be
uplinked to the surface for use in calculating an appropriate kill
mud weight or for some other purpose.
[0013] It should be understood that examples of the more important
features of the invention have been summarized rather broadly in
order that detailed description thereof that follows may be better
understood, and in order that the contributions to the art may be
appreciated. There are, of course, additional features of the
invention that will be described hereinafter and which will form
the subject of the claims appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] For detailed understanding of the present invention,
references should be made to the following detailed description of
the preferred embodiment, taken in conjunction with the
accompanying drawings, in which like elements have been given like
numerals and wherein:
[0015] FIG. 1 schematically illustrates a well construction system
utilizing a downhole well control device made in accordance with
the present invention;
[0016] FIG. 2 schematically illustrates one embodiment of a well
control device made in accordance with the present invention;
[0017] FIG. 3 illustrates a flow chart showing one exemplary
methodology for controlling a well kick in accordance with the
present invention;
[0018] FIG. 4 illustrates a flow chart showing one exemplary
methodology for controlling a fluid loss in a wellbore in
accordance with the present invention;; and
[0019] FIG. 5 illustrates a flow chart showing one exemplary
methodology for controlling an underground blowout in accordance
with the present invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0020] The present invention relates to devices and methods for
control of fluid flow in a wellbore. The fluid may be a liquid, a
gas, a slurry or mixtures of same. The present invention is
susceptible to embodiments of different forms. There are shown in
the drawings, and herein will be described in detail, specific
embodiments of the present invention with the understanding that
the present disclosure is to be considered an exemplification of
the principles of the invention, and is not intended to limit the
invention to that illustrated and described herein.
[0021] Referring initially to FIG. 1 there is shown a schematic
diagram of a well construction system 10 having one or more well
tools 12 shown conveyed in a borehole 14 formed in a formation 16.
The system 10 can be configured for performing one or more
operations related to the construction, logging, completion or
work-over of a hydrocarbon producing well. In particular, FIG. 1
shows a schematic elevation view of one embodiment of a wellbore
drilling system 10 for drilling a wellbore 14 using conventional
drilling fluid circulation. The drilling system 10 is a rig for
land wells but can be a drilling platform, which may be a drill
ship or another suitable surface workstation such as a floating
platform or a semi-submersible for offshore wells. For offshore
operations, additional known equipment such as a riser and subsea
wellhead will typically be used. The system 10 includes a
conventional derrick 18 erected on a floor 20. A string 24, such as
a tool string, work string, or drill string, extends downward from
the surface into the borehole 14. The string 24 can be formed
partially or fully of drill pipe, metal or composite coiled tubing,
liner, casing or other known members. Additionally, the tubing
string 24 can include data and power transmission carriers such
fluid conduits, fiber optics, and metal conductors. The string 24
and well tool 12 can include any type of equipment including a
steerable drilling assembly, a drilling motor,
measurement-while-drilling assemblies, formation evaluation tools,
drill collars or drill pipe. For simplicity, a bottomhole drilling
assembly (BHA) 26 is showing having a drill bit 28 and attached to
the end of the drill string 24. The bit can be rotated by a surface
rotary drive or a motor using pressurized fluid (e.g., mud motor)
or an electrically driven motor. To drill the wellbore 14, the BHA
26 is conveyed to the wellhead equipment 30 and then inserted into
the wellbore 14 using a suitable system. Additionally a surface
controller 31 can be connected to system 10 to provide automated or
semi-automated control over the system 10. The controller 31 can
also be operatively coupled to a suitable communication device (not
shown) that provides communication with downhole equipment. In one
embodiment, the suitable communication device is configured to
transmit downlinks encoded with instructions for operation of the
well control device 200. In other embodiments, the suitable
communication device is also configured to receive uplinks encoded
with data relating to sensor measurements or the operating status
of the well control device 200.
[0022] To drill the wellbore 14, well control equipment 30 (also
referred to as the wellhead equipment) is placed above the wellbore
14. The wellhead equipment 30 includes a surface blow-out-preventer
(BOP) stack 22 and a lubricator (not shown) with its associated
flow control. Additionally a surface choke 35 in communication with
a wellbore annulus 40 can control the flow of fluid out of the
wellbore 14 to provide a back pressure as needed to control the
well.
[0023] During drilling, a drilling fluid from a surface mud system
34 is pumped under pressure down the drill string 24. The mud
system 34 includes a mud pit 36 and one or more pumps 38. The drill
bit 28 disintegrates the formation (rock) into cuttings. The
drilling fluid leaving the drill bit travels uphole through an
annulus 40 between the drill string 24 and the wellbore wall,
carrying the entrained drill cuttings. The return fluid discharges
into a separator (not shown) that separates the cuttings and other
solids from the return fluid and discharges the clean fluid back
into the mud pit 36.
[0024] Once the well 14 has been drilled to a certain depth, casing
46 with a casing shoe 48 at the bottom is installed. The drilling
is then continued to drill the well to a desired depth that will
include one or more production sections, such as section 50. The
section below the casing shoe 48 may not be cased until it is
desired to complete the well, which leaves the bottom section of
the well as an open hole, as shown by numeral 52.
[0025] In one embodiment, the drilling system 10 includes a well
control device 200 that controls the rate of flow, the direction of
flow and/or the conduits or paths in which one or more fluids flow.
As will be seen, the well control device 200 in cooperation or
independent of the surface blow-out preventer stack 22 and other
surface equipment can exert control over one or more parameters
relating to wellbore fluids or the formation in order to manage an
out-of-norm wellbore condition such as a kick or a fluid loss into
a formation. By out-of-norm condition, it is meant any condition
that could pose a hazard to personnel, the environment, or
equipment. Out-of-norm conditions also include conditions that
could interrupt work activities or damage the well.
[0026] Embodiments of the well control device 200 can be used to
hydraulically isolate sections of the wellbore. The out-of-norm
condition associated with one or more of these isolated wellbore
sections can then be treated independently. Referring now to FIG.
2, there is schematically shown a well control device 200 in a
wellbore 14. When activated, the well control device 200
hydraulically isolates a lower wellbore section 205 from an upper
wellbore section 207. This can be advantageous, for instance, when
the two sections 205 and 207 are encountering different out-of-norm
conditions; e.g., the upper wellbore section 207 could encounter a
loss of fluid into the formation, shown by arrows L, and/or the
lower wellbore section 205 could encounter a kick, shown by arrows
K. The well control device 200 allows each section 205, 207 to be
controlled or treated separately, which can provide greater
flexibility in selection of an appropriate course of remedial
action. Additionally, the well control device 200 can provide
selective circulation of fluid in each of the sections 205, 207 by
using bypass devices. The isolation need not necessarily be
complete. Rather, the isolation may be to a degree substantial
enough to implement a desired remedial action. Thus, terms
"isolate" or "isolation" as used herein is not intended to mean or
require absolutely no fluid communication across a barrier or
equipment.
[0027] As shown in FIG. 2, the downhole well control device 200 may
be positioned along a section of a bottomhole assembly (BHA) 202 or
positioned uphole of the BHA 202 in a separate section of the drill
string 24. The well control device 200 can be positioned anywhere
along the BHA 202 or drill string 24, including the open hole
section of the wellbore. In one embodiment, the device 200 includes
an annulus seal 210 that controls flow in the well annulus 40, a
pipe bore valve 220 that controls flow in the pipe bore 222 and a
bypass valve 230 that can direct flow between the annulus 40 and
the pipe bore 222. The terms seals, packers and valves are used
herein interchangeably to refer to flow control devices that can
selectively control flow across a fluid path. The control can
include providing substantially unrestricted flow, substantially
blocked flow, and providing an intermediate flow regime. The fluid
barrier provided by these devices can be "zero leakage" or allow
some controlled fluid leakage. In some embodiments, the seals and
valves are responsive to command signals. Suitable flow control
devices include packer-type devices, expandable seals, solenoid
operated valves, hydraulically actuated devices, and electrically
activated devices.
[0028] In one arrangement wherein the annulus seal 210 utilize one
or more inflatable packers, the annulus seal 210 may be activated
in the following manner. First, drilling fluid is circulated using
the surface mud pumps 38 (FIG. 1). While the mud pumps 38 are
operating, the bypass 230 is initially opened and the bore valve
220 is closed. Thereafter, the flow across the bypass 230 is
modulated, e.g., restricted, to create a bore-to-annulus
differential pressure. This differential pressure inflates the
inflatable packer. Suitable valves (not shown) direct fluid to and
from the inflatable packer.
[0029] Referring now to FIGS. 1 and 2, the well control device 200
may in one arrangement be activated by a downlink in the form of a
flow variation. In another arrangement, an activation downlink or
signal may be encoded into a pressure sequence. For example,
initially, the pipe bore valve 220 may be normally closed prior to
drilling operation. To start drilling, pressure in the drill string
24 may be built up quickly via the surface pumps 38. Once the
pressure in the bore of the drill string 24 exceeds a predetermined
trigger pressure, the pipe bore valve 220 opens and the pressure in
the bore of the drill string 24 drops to a desired operation
pressure. To activate the well control tool 100, the pressure in
the drill string 24 is increased to within a predetermined pressure
window, which may be lower than the trigger-pressure, and held
there for a predetermined time period. Mechanical devices, such as
springs, and/or hydraulic devices, such a metered nozzle,
responsive to the pressure variation thereafter activate the well
control tool 200. Alternatively, sensors in the drill string 24 may
be used to detect that the trigger pressure has been reached and
maintained for the required time period.
[0030] Additionally, a downhole controller 240 controls the
operation of the seal and valve 210, 220, the bypass valve 230 and
other associated equipment described below. A communication device
242 transmits signals between the controller 240 and surface
equipment and personnel. In one embodiment, the communication
device 242 is configured to receive downlinks encoded with
instructions for operation of the well control device 200. In other
embodiments, the communication device 242 is also configured to
transmit uplinks encoded with data relating to sensor measurements
or the operating status of the well control device 200. Thus, the
communication device 242 can be both one-directional and
bidirectional. The physical position of the communication device
will depend on the type of communication system used. For instance,
a system that utilizes flow variations or pressure pulses, the
device 242 would likely be positioned uphole of the pipe valve 220.
The BHA 202 can also include one or more sensors 244 for measuring
parameters of interest such as formation parameters, the BHA
operating parameters, drilling parameters, etc.
[0031] In a normal operating condition, the annulus seal 210 and
the pipe bore valve 220 are in a de-activated condition and permit
unrestricted fluid flow through the annulus 40 and pipe bore 222,
respectively. The bypass valve 230 is positioned uphole of the seal
and valve 210, 220 and is normally closed to prevent flow between
the annulus 40 and the pipe bore 222. Thus, for example, during
drilling, the drilling fluid flows down via the pipe bore 222 and
returns with entrained cuttings via the annulus 40. In an out of
norm condition, e.g., a well kick, the bypass valve 230 and the
seal and valve 210, 220 can be activated independently or together
to stabilize and control the out of norm condition. For example,
the seal and valve 210, 220 can be activated to stop fluid flow in
the annulus 40 and the pipe bore 222. In this condition, the
section of the wellbore downhole 205 of the device 200 will be
substantially hydraulically isolated from the section of the
wellbore uphole 207 of the device 200. Further, by opening the
bypass valve 230, fluid can be circulated in the uphole wellbore
section 207, while maintaining a specified wellbore condition in
the downhole wellbore section 205. This flow control regime is
merely illustrative of the well control provided by the well
control device 200. Still other illustrative flow control regimes
will be discussed in detail below.
[0032] In one embodiment, the bypass valve 230 may be operated to
transmit uplinks. The uplinks, or data signals, may include sensor
measurements, equipment operating conditions, status, etc. In an
exemplary arrangement, the pipe bore 222 is closed and circulation
is established in the uphole section 207. Thereafter, the bypass
valve 230 may be modulated using the controller 230 or other
suitable device to cause pressure fluctuations in the drill string
24 or the annulus 40. That is, closing the valve 230 may cause a
pressure increase, or positive pressure pulse, in the drill string
24 and a pressure drop, or negative pressure pulse, in the annulus
40. Because either or both of these pulses can be detected at the
surface, these pulses may be used to transmit data from downhole to
the surface. For example, the magnitude or frequency of the pulses
may be controlled to convey information. Additionally, the time
between pulses may be controlled as a method to convey
information.
[0033] The controller 240 contains one or more microprocessors or
microcontrollers for processing signals and data and for performing
control functions, solid state memory units for storing programmed
instructions, models (which may be interactive models) and data,
and other necessary control circuits. In other embodiments, the
controller 240 can be a hydro-mechanical device that incorporates
known mechanisms (valves, biased members, linkages cooperating to
actuate tools under, for example, preset conditions).
[0034] The communication device 242 can utilize any number of media
and methodologies to provide the transfer of data, signals and
commands between the surface and the well control device 200.
Exemplary communication devices can utilize data encoded flow
and/or pressure variations, acoustic signals, mud pulse telemetry,
EM telemetry, and signals carried via conductors such as optical
fibers or electrical conductors. In one arrangement, downhole
reception of a downlink is enabled by downhole measurement of the
flow rate or flow variations, e.g., via the rotational speed of a
downhole turbine or positive displacement motor, or measurement of
the downhole pressure change caused by the change in flow rate. If
a pressure sensor is used, down links can be established when the
pipe bore 222 is blocked below the well control device 200 by, for
example, varying the pipe pressure using the surface pumps 38.
[0035] Other methodologies for transmitting a signal or signals
downhole include varying the rotational speed of the drill string
24, altering the WOB, and axially manipulating the drill string 24.
For example, deactivation of the well control tool 200 may be
initiated by pulling or rotating the drill string 24, which creates
a detectable relative movement, force and/or torque because a part
of the well control tool 200, such as an expanded packer element,
is fixed to the wellbore wall when activated. In still another
methodology, an object such as a ball or dart can be pumped into
the wellbore to activate the well control device 200 by, for
example, occluding the bore 222 and thereby increasing the pressure
in the bore 222 or by physically engaging a switch or other
suitable actuating member (not shown). Devices suitable for
transmitting an uplink and/or a downlink include wired pipe,
acoustic transmitters such as piezoelectric devices, mud sirens,
mud pulsers, and dynamic valves. As will be seen, each may present
a particular advantage in a particular situation and it should be
understood that the present invention is not limited to the
communication methodologies and devices listed above.
[0036] Power for the well control device 200 can be provided by one
or more downhole batteries, a downhole generator or an accumulator.
Also, the high pressure mud can also be used to energize the
several components of the well control device 200. In some
embodiments, devices for generating power such as mud turbines can
be supplemented using arrangements such as bypass valves to allow
power generation and flow measurement over a wider range of flow
rates than normally possible.
[0037] In FIG. 3, there is shown an illustrative method 300 for
using the well control device 200 in a well kick situation.
Referring now to FIGS. 1-3, initially, a kick detection 302 can be
made either at the surface 306 or downhole 308. A surface detection
306 can be made by monitoring the volume and flow of mud into the
pit, an increase being indicative of a well kick. A downhole
detection 308 can be made by sensors 244 at the well control device
200, which then is transmitted by an uplink 310 to surface
controller 31. The surface controller 31, using preprogrammed
instructions or by prompting a human operator, can initiate a
decision process 314, which can include verifying the detected kick
and whether rotation has to be stopped to allow for well control
device 200 activation. Subsequently, well control device 200
activation is initiated by a downlink 316.
[0038] In one variant, the downlink 316 to activate the well
control device 200 may be proceeded by a surface shut-in 320 using
conventional equipment. Appropriate measurements can be made, such
as measuring surface pressures 322. Based on measured and/or
calculated data, a suitable kill mud weight is determined 324 and
circulated into the well using a choke 35 that applies 326 a
suitable back pressure to control the well kick. Alternatively, the
original drilling fluid can be circulated with an appropriate choke
control 328. Such a process can allow an earlier stop of the influx
and determination of the kill mud weight.
[0039] In another variant, an in situ decision 330 to activate the
well control device 200 is made by a downhole controller 240 which
sends 332 an uplink encoded with its decision to surface.
Optionally, the downhole controller 240 can monitor one or more
selected parameters (e.g., string RPM) 334 for a signal to proceed
with the well control device 200 activation sequence.
[0040] Upon activation 318, the well control device 200 seals off
the pipe bore 222, seals off the annulus 40, and opens the bypass
valve 230. At this time, the kill mud weight can be determined or
updated from the downhole shut-in pressure 336 which is measured
and uplinked 336 by the well control device 200. Meanwhile,
circulation of kill mud 340 above the well control device 200 is
maintained while the surface choke 35 is used to circulate out
formation fluids that were not shut-in below the well control
device 200. Optionally, uplinks 348 may continue during this
"killing" operation, allowing for corrections/updates with respect
to the kill mud weight to be made.
[0041] Completion of this stage, which can include the annulus 40
above well control device 200 being full of kill mud of sufficient
density, is determined 342 by a surface controller 31 that
subsequently sends a downlink 344 to deactivate the well control
device 200. In a variant, a downhole controller 240 may
automatically determine completion of the stage 350 and deactivate
the well control device 200. To notify surface of successful
deactivation, the well control device 200 can, optionally, send an
uplink 354.
[0042] After well control device 200 deactivation, any formation
fluids below the well control device 200 annulus seal 210 can be
circulated out 352 conventionally via the surface BOP 22 and choke
35. It should be appreciated that the annular pressure at the
casing shoe 48, or other weak open hole location, is smaller than
in a conventional kill operation. This is due to the kick volume
below the well control device 200 being generally smaller than the
total kick volume in a conventional kill operation and the annulus
40 between the well control device 200 and the casing shoe 48 being
filled with the kill mud rather than drilling fluid, which reduces
the pressure required at the casing shoe.
[0043] In FIG. 4, there is shown an illustrative method 400 for
using the well control device 200 in a situation where drilling
fluid is being lost to the formation due to weak formations.
[0044] Referring now to FIGS. 1, 2 and 4, after losses have been
detected 402, either at the surface or downhole, a downlink 404 is
sent to activate 406 the well control device 200 via a downlink. If
the level of fluid in the mud pit 36 continues to drop or if
annular mud level cannot be maintained, then it is likely that
fluid is being lost to a formation above the well control device
200. If the level of fluid in the mud pit 36 stabilizes and annular
mud level can be maintained, then it is likely that fluid is being
lost to a formation below the well control device 200.
[0045] In the scenario where mud is lost above the well control
device 200, the losses are treated by circulating 408 lost
circulation material (LCM) above the well control device 200 using
the open bypass valve 230. It should be appreciated that a
conventional kick below the well control device 200 due to
insufficient annular mud level is prevented because the well
control device 200 has sealed off the annulus 40 to thereby
maintain a suitably high annular pressure in the section below the
well control device 200. After losses are cured, a downlink 410 is
used to de-activate 412 the well control device 200. Optionally, a
confirmation uplink can be transmitted 416 for the
de-activation.
[0046] In the scenario where losses occur below the well control
device 200, the entire annulus 40 above the well control device 200
can be maintained full of mud and, therefore, kicks due to
insufficient mud level are prevented across the entire open hole
section above the well control device 200 and below the casing shoe
48.
[0047] To control the well in this scenario, drilling fluid is
circulated 418 to remove cuttings. Then, after cuttings are
circulated out, the LCM is added 420 to the mud being pumped down.
At this point, there are at least three options for pumping LCM
into the loss zone below the well control device 200.
[0048] The first option involves closing the bypass valve 230. To
avoid either further fracturing the loss zone or triggering the
pressure relief valves at surface while the bypass closes,
circulation is stopped 424 after the activation downlink 422 has
been sent. After the bypass is closed 426 and the pipe valve 220 is
opened, LCM can be forced 428 into the loss zone by slowly bringing
up the pumps 38 because the annulus seal 210 is still closed. When
losses have been treated sufficiently, e.g., as detected by
standpipe pressure (SPP) exceeding a threshold, the pumps 38 are
stopped 430 and the well control device 200 is deactivated 432.
Several de-activation options 434 are available, including but not
limited to a downlink signal or a timer that deactivates the well
control device 200 after a pre-set duration.
[0049] In a variant, the loss could be treated with cement. If so,
then after completing step 418, the well control device 200 is
de-activated 436, the bit is pulled off bottom 438 by a certain
distance, and the well control device 200 is re-activated 440.
Thereafter, steps 422-426 are followed. At this point, cement is
pumped 442. After the pump 38 is secured 444, the cement is allowed
to set before well control device 200 deactivation 432.
[0050] The second option maintains the bypass valve 230 in an open
position and uses a non-return valve to prevent flow from the
annulus 40 into the pipe bore 222 through the bypass valve 230. The
non-return valve prevents the annulus mud level from dropping once
a connection to the loss zone is established when the pipe valve
220 opens. In this second option, a downlink is sent 450 that opens
452 the pipe valve 220. Circulation of LCM, which was initiated at
step 420, continues until full returns are seen at surface, which
indicates that losses have stopped. A downlink is then sent 454 to
close 456 the pipe valve 220, which then is followed by
de-activation 458 of the well control device 200. Optionally, a
confirmation uplink is sent 460 to confirm deactivation.
[0051] The third option maintains the bypass valve 230 in an open
position without using a non-return valve. Instead, a downlink is
sent 462 that causes the pipe valve 220 to only partially open 464
("choked" pipe flow) to prevent a situation in which the flow into
the loss zone exceeds the pump rate so that mud is drawn from the
annulus 40 and the level drops. To avoid this and, at the same
time, maximize the flow of LCM into the loss formation, the pipe
valve 220 can be adjusted in closed-loop control 466. The control
variable could be the annulus pressure above the annulus seal 210
because dropping annulus level leads to dropping annulus pressure.
The control variable could also use a measurement of the bypass
flow, which must be greater than or equal to zero to avoid dropping
annulus level. As in the second option, success of the losses
treatment is indicated by full returns at surface and subsequent
procedural steps are equivalent to the second option.
[0052] In FIG. 5, there is shown an illustrative method 500 for
using the well control device 200 to control an underground
blowout, that is, downhole losses and kicks occur
simultaneously.
[0053] Referring now to FIGS. 1, 2 and 5, in one scenario, an
underground blowout results from a shut-in 502 at surface in order
to control a kick. In some situations, the well control device 200
is located between the kick and the loss zone and, when activated,
provides zonal isolation between the two zones. For a downlink
using circulating fluid, circulation and appropriate choke control
is resumed 504 to maintain downhole pressures at the desired level
and an activation downlink is sent 506. For a downlink that does
not require circulation, a downlink is sent 510 for activation. A
downhole source, such as a battery can provide the necessary power
to enable activation of the well control device 200.
[0054] Upon well control device 200 activation 508, the position of
the loss zone relative to the annulus seal 210 can be determined
510. If the level of fluid in the mud pit 36 continues to drop or
if annular mud level cannot be maintained, then it is likely that
fluid is being lost to a formation above the well control device
200. If the level of fluid in the mud pit 36 stabilizes and annular
mud level can be maintained, then it is likely that fluid is being
lost to a formation below the well control device 200.
[0055] Losses above the seal 210 can be treated by circulating 512
LCM. Parameter such as level of the mud pit 36 can be monitored 514
until a controller 31, 240 determines 516 that losses have stopped.
After losses are stopped, kill mud, with or without LCM, can be
circulated 518 in above the well control device 200. The bottomhole
pressure measurement required for determining the kill mud weight
can be uplinked continuously from the moment the well control
device 200 is activated. Thereafter, steps 336-352 of FIG. 3 are
executed to control the well.
[0056] For losses below the well control device 200 and the kick
above the well control device 200, the annulus 40 is first refilled
526. Next, a standard kill procedure utilizing the surface choke 35
and the BOP 22 is applied 528 to kill 530 the kick. In a variant,
the kill procedure may be preceded by a preparation for cementing
the loss zone by steps 520, 522, 524, which have been previously
discussed in connection with steps 436, 438 and 440 of FIG. 4.
After the well is killed above the well control device 200, two
options are available. First, the procedure starting at step 420 of
FIG. 4 can be followed. Second, LCM can be added 532 to the kill
mud and a downlink sent 534 to deactivate 536 the well control
device 200.
[0057] In another aspect, embodiments of the present invention can
utilize downhole pressure measurements to determine parameters such
as wellbore pressure. For example, conventionally, after a surface
shut-in, the stand pipe pressure is measured to determine wellbore
pressure. Embodiments of the present invention can, after
activation of the well control device 200, measure the pressure of
the fluid in the annulus 40 or the pipe bore 222 below the well
control device 200 to determine wellbore pressure. This pressure
measurement can be uplinked to the surface for use in calculating
an appropriate kill mud weight or for some other purpose. In still
another aspect, embodiments of the present invention may utilized
surface measured or estimated shut-in pressure. Referring now to
FIG. 2, In one arrangement, shut-in pressure may be measured as
follows. The annulus seal 210 may be activated while keeping the
bore valve 220 open and the bypass 230 closed. With the well
control equipment in this configuration, the shut-in drill-pipe
pressure (SIDPP) may be measured or estimated at the surface using
conventional sensors. It will be appreciated that such a
measurement of SIDPP reduces the likelihood of errors caused by
losses occurring in the wellbore above the annulus seal 210.
[0058] It should be appreciated that the teachings of the present
invention can be applied to a variety of out-of-norm well
conditions, not just those described above. The devices and
embodiments described above, therefore, are merely illustrative of
the arrangements useful in controlling or managing a particular
out-of-norm well condition For example, in some instances, two or
more well control devices may be positioned along the wellbore to
provide zonal isolation and zoned circulation for multiple isolated
zones.
[0059] The foregoing description is directed to particular
embodiments of the present invention for the purpose of
illustration and explanation. It will be apparent, however, to one
skilled in the art that many modifications and changes to the
embodiment set forth above are possible without departing from the
scope of the invention. It is intended that the following claims be
interpreted to embrace all such modifications and changes.
* * * * *